As is well known in the hydrocarbon industry, many wells require “stimulation” in order to promote the recovery of methane from the coal bed methane (CBM) production zone of the well. CBM is also known as NGC (natural gas from coal), CBG (coal bed gas) and CSM (coal seam methane).
One of these stimulation techniques is known as “fracturing” in which a fracturing fluid composition is pumped under high pressure into the well together with a proppant such that new fractures are created and passageways within the CBM production zone are held open with the proppant. Upon relaxation of pressure, the combination of the new fractures and proppant having been forced into those fractures increases the ability of methane to flow to the wellbore from the CBM production zone.
There are a significant number of fracturing techniques and fluid/proppant compositions that promote the formation of fractures in the CBM production zone and the delivery of proppants within those fractures. The most commonly employed methodologies seek to create and utilize fracturing fluid compositions having a high viscosity that can support proppant materials so that the proppant materials can be effectively carried within the fracturing fluid. In other words, a viscous fluid will support a proppant within the fluid in order that the proppant can be carried a greater distance within the fracture, or in some circumstances, carried at all. In addition, fracturing fluids are commonly designed such that upon relaxation of viscosity (or other techniques) and over time (typically 90 minutes or so), the fluid viscosity drops and the proppant is “dropped” in the formation and the supporting fluid flows back to the wellbore. The proppant, when positioned in the fracture seeks to improve the permeability of the CBM production zone in order that methane will more readily flow to the well. An effective fracturing operation can increase the flow rate of methane to the well by at least one order of magnitude. Many wells won't produce long term in an economic manner without being stimulated by methods such as fracturing.
Fracturing fluid compositions are generally characterized by the primary constituents within the composition. The most commonly used fracturing fluids are water-based or hydrocarbon-based fluids, defined on the basis of water or a hydrocarbon being the primary constituent of the specific composition. Each fracturing fluid composition is generally chosen on the basis of the subterranean formation characteristics and economics. In general, a production zone that produces in situ formation water is usually economically stimulated with a water-based system. For CBM formations, which are commonly water producing before they produce methane, an economic water-based fluid is a common choice whereas hydrocarbon based fluids are not used very often.
In the case of water-based fluids, in order to increase the viscosity of water, various “viscosifying” additives may be added to the water-based fluid at the surface such that the viscosity of the water-based fluid is substantially increased thereby enabling it to support proppant. As is known, these water-based fluids may include other additives such as alcohols, KCl and/or other additives to impart various properties to the fluid as known to those skilled in the art. The most commonly used viscosifying additives are polymeric sugars that are used to create linear gels having moderate viscosities. These linear gels may be further combined with cross-linking agents that will create cross-linked gels having high viscosities.
CBM formations generally naturally fracture with a primary set of natural fractures (face cleats) located perpendicular to a secondary set of natural fractures (butt cleats). In the past 20 years, many CBM wells were stimulated with cross-linked water-based fracturing fluids and foam fracturing fluids. However currently, unconventional reservoirs, including CBM formations, are generally pumped with low viscosity fluids such as slick (friction reduced) water and nitrified (up to 53% quality) slick water fracture compositions. Where traditional high viscosity fluids typically encourage a bi-wing fracture (two single fractures extending out from opposing sides of the well bore) by plugging secondary (usually orthogonal) fractures, low viscosity fluids generally are less likely to plug secondary fractures, thus forming a wide intersecting fracture network instead.
In the case of CBM production zones, there are generally two basic types: dry CBM production zones and wet (water containing) CBM production zones. In both cases, methane typically exists in two possible forms within the production zone. The first form is a free gas (gaseous state) where methane gas exists in the porosity of the formation, which is mostly in the natural fractures. The second form of methane is adsorbed onto the surface of the coal in equilibrium with reservoir pressure. If reservoir pressure increases, more free gas adsorbs onto the coal surface. If reservoir pressure decreases, more methane desorbs off of the coal surface to become free gas.
Stimulating production of a CBM production zone generally depends on the basic type of production zone (dry or water containing). If the CBM production zone is dry, the methane will generally desorb off the coal surfaces and flow to the well as a gas if the pressure of the well is lowered through well operations at the surface. If the CBM production zone is water containing, the reservoir pressure generally needs to be reduced through a process called dewatering. Dewatering is a well operation where water is pumped from the well to reduce pressure in the reservoir until methane starts to desorb off of the coal surface. As more water is removed from the reservoir, more methane desorbs from the coal surfaces at a faster rate. This process typically continues until poor economics of the well develop, due in part to eventually declining rates of methane production. Dewatering rates traditionally have been high, in the order of 30 m3/day, where current dewatering rates can be limited to maximum as low as 3 m3/day to maintain created and natural fracture permeability by not causing fractures to close.
During a typical fracturing operation, the fracturing fluid (without any proppant) is initially pumped into the well at a sufficiently high pressure and flow rate to fracture the formation, or in the case of CBM formations, to also dilate and/or re-open pre-existing natural fractures. After fracturing has been initiated, a proppant is generally added to the fracturing fluid, and the combined fracturing fluid and proppant is forced into the fractures in the CBM production zone. When pressure is released and over time (typically 90 minutes), the viscosity of the fracturing fluid drops such that the proppant separates or drops out of the fracturing fluid within the formation, and the “de-viscosified” fracturing fluid flows back to the well where it is removed.
One major problem in this type of fracturing is the large volumes of water required and the attendant issues relating to the disposal of the water that has been pumped downhole and ultimately recovered from the well as a coal particle or otherwise contaminated fluid. Naturally fractured formations in the past few years have responded quite well to slick water based fractures, however, these types of fractures can use extremely high volumes of water, generally 2 to 3 orders of magnitude higher than traditional fracturing methods in CBM production zones. For example, where a normally sized foam frac typically used 30 m3 of water in a CBM well 10 years ago, a slick water fracture with current technology can require 3,000 m3 of water. In the case that the well has a dry CBM production zone, often having very low reservoir pressures, injecting extremely large volumes of water can counteract the benefit of forming a wide intersecting fracture network. In the case that the well has a wet CBM production zone, some current dewatering practices have rates that can be as low as 3 m3/day and that can extend the lengths of time by months or years for steady methane production due to adding a large volume of fracturing water to the large volumes of reservoir water that already needs to be removed. As a result, in some cases the industry has required a reduction in water use while still maintaining a wide network of fractures by moving away from pure water-based fracturing fluids in favor of those technologies that utilize a high proportion of gas (usually nitrogen or supercritical carbon dioxide) as the fracturing fluid.
Generally, the use of a high proportion of gas in a fracturing fluid has several advantages, including minimized formation damage, reduced fluid supply costs and reduced disposal costs of fluid recovered from the well. For example, whereas water may increase the time required to dewater a CBM production zone to start flowing significant amounts of methane, high gas compositions may minimize such effects and will otherwise migrate from the formation more readily, and encourage larger amounts of fracturing water to flow back immediately after the fracturing operations. Gas injected and thus recovered from a well can simply be released to the atmosphere thereby obviating the need for decontamination and disposal of a substantial proportion of the materials recovered from the well.
With high ratio gas fracturing compositions, the characteristics of the compositions can be similarly controlled or affected by the use of additives. Generally, gas fracturing compositions can be characterized as a pure gas fracturing composition (typically a fluid comprising around 100% CO2 or nitrogen) or energized, foamed and emulsied fluids (typically a fracturing composition comprising less than about 85% CO2 or nitrogen by volume).
A pure 100% gas fracturing composition will have minimal viscosity and instead will rely on high turbulence to transport proppant as it is pumped into the CBM production zone. Unfortunately, while such techniques are effective in limited batch operations, the need for expensive, highly specialized, pressurized pumping, mixing and containment equipment substantially increases the cost of an effective fracturing operation. For example, a fracturing operation that can only utilize a batch process is generally limited in size to the volumetric capacity of a single pumping and containment unit. As it is economically impractical to employ multiple units at a single fracturing operation, the result is that very high volume gas fracturing operations can only be effectively employed in relatively limited circumstances. For example, a pure gas fracturing operation would typically be limited to pumping 300-32,000 kg of sand (proppant) into a well and is limited to the type of proppant that can be used in some circumstances. Common 100% gas fracturing compositions, such as liquid carbon dioxide or gelled propane, are inherently not preferred for CBM wells due to the chemical adsorption, methane desorption interference or damage that can occur on the surfaces of the coal to affect the long term production ability of the CBM production zone.
In the case of some shallow, dry and severely under-pressured CBM production zones, the reservoir often has high permeability, often due to being naturally fractured. During the drilling, casing and cementing process, the CBM production zone may be damaged or plugged such that perforations alone can't adequately communicate the well with the reservoir. A pure gas fracturing technique without proppant may be used to break through the damaged area and/or unplug the blocked area that prevents the methane flowing into the well from the CBM production zone. For example, high rate nitrogen is injected into a shallow coal bed methane CBM production zone at a rate of 1000 to 1500 scm/min for a volume of 3000 to 5000 scm (just a few minutes total operation) to unplug the damage and allow the CBM production zone to flow into the well. Due to economical requirements, comingling CBM production with conventional production from normally pressured sandstone or other lithologies is required. In the case that these conventional production zones are stimulated with proppant and fluids, as is often practiced, cross-flow can occur where gases and fluids from any one production zone may flow into any other production zone due to reservoir pressure differences either in a short time or long time after the stimulation. Where the conventional zones commonly have higher pressures than the under-pressured coal zones, there are inherently higher risks. Often it is desired that the fracturing compositions and methods used in the conventional zones be chemically compatible and prevent damage to the CBM zones if they are exposed or otherwise meet any environmental and non-toxic requirements.
In the case of some shallow, dry and severely under-pressured CBM production zones, the reservoir may have lower permeability than economically acceptable if high rate nitrogen stimulations are performed. In the case of most lower permeability production zones, a proppant fracture creating highly permeable paths for methane to flow to the well from the reservoir is required. Due to the low reservoir pressure, any normal amount of fracturing fluid may hydrostatically cause a water block which could prevent methane production as the reservoir pressure would be increased as well as a second phase being introduced to a pure gas system causing relative permeability reduction effects to methane flow.
The use of non-energized, energized, foamed and emulsied fluids for fracturing are generally not limited to batch operations as fluid mixing and pumping equipment for such fluids is generally not at the same scale in terms of the complexity and cost of equipment that is required for pure gas operations. In other words, the mixing and pumping equipment for a non-energized/energized/foamed/emulsied fluid fracturing operation is substantially less expensive and importantly, can produce effectively large continuous volumes of fracturing fluid mixed with proppant. That is, while a 100% gas fracturing operation may be able to deliver up to 32,000 kg of proppant to a formation, a non-energized/energized/foamed/emulsied fluid fracturing operation may be able to deliver in excess of 10 times that amount.
The characteristics of energized, foamed and emulsied fluids are briefly outlined below as known to those skilled in the art.
An energized fluid will generally have less than 53% (volume %) gas together with a conventional gelled water phase. An energized fluid is further characterized by a continuous fluid phase with gas bubbles that are not concentrated enough to interact with each other to increase viscosity. For example, the overall viscosity of an energized fluid comprised of a linear gel and nitrogen gas may be in the range of 20 cP which is a “mid-point” between the viscosity of a typical linear-gel water phase (30 cP) and a nitrogen gas phase (0.01 cP). For a cross-linked gel, the viscosity range may be 150-1000 cP (typically 100-800 cP when mixed with gas). However, in the case of high viscosity fluids, such as cross-linked gel, the desired wide fracturing network is not as likely to occur during fracturing, and in most cases the cross-linking agent is toxic. As is known, and in the context of this description, viscosity values measured in centipoise (cP) are dependent on shear rate. In this specification, all viscosity values are referenced to a shear rate of 170 sec−1.
Foams will generally have greater than 53 vol % gas but less than about 85 vol % gas with the remainder being a gelled water phase. Foams are characterized as having a continuous fluid film between adjacent gas bubbles where the gas bubbles are concentrated enough to interact with each other to increase viscosity. Foams require the addition of foaming agents that promote stability of the gas bubbles. The viscosity of a foam will typically be in the range of 200-300 cP which may be 10 times greater than the viscosity of the gelled water phase (20-30 cP) and many times greater than the viscosity of the gas phase (0.01-0.1 cP). However, the greater viscosities may decrease the desired effect of forming a wide intersecting fracture network relative to lower viscosity systems absent of foamer. As known to those skilled in the art, most foaming agents will interfere or otherwise have a damaging effect with respect to the desorption process of methane from the coal faces in the production zone. In addition, most foaming agents do not pass relevant toxicity tests.
A carbon-dioxide emulsion, also known as a carbon-dioxide foam, is where the internal phase is a carbon-dioxide supercritical fluid and is characterized by having a second liquid film (i.e. the water-based phase) between adjacent liquid droplets. Emulsions will generally form when the supercritical fluid concentration is greater than 53 vol % and less than about 85 vol %. Emulsions require the addition of foaming agents to promote stability. The viscosity of an emulsion may also be 10 times greater than the individual viscosities of the separate gelled water phase and supercritical gas phase. Again, the higher viscosity emulsion will discourage the creation of wide intersecting fracture networks, which is desired in unconventional reservoirs. Furthermore, 100% carbon dioxide gas phases may damage CBM production zones by preferentially adsorbing on coal faces compared to methane such that permeability decreases (may be up to a 4 fold decrease) due to swelling decreasing the porosity and openness of the natural fractures.
Finally, when the gas concentration is increased above about 85% (typically 90-97%), the stability of a typical emulsion or a foam will decrease, such that the emulsion or foam will “flip” such that the gas phase becomes continuous, and the water phase is dispersed with the gas phase as small droplets or in larger slugs. This is commonly referred to as a “mist”. The viscosity of a mist will generally revert to a “mid-point” of viscosity close to that of the gas (i.e. approximately 1-3 orders of magnitude lower than that of an emulsion) with the result being that the ability to support proppant based on viscosity is lost. As a result, fracturing compositions generally avoid the formation of mists and instead favor stabilizing foams and otherwise maximizing viscosities.
However, the tendency of developing a wide intersecting fracture network may increase when using a mist, while the volume of water needed is drastically reduced, and therefore less total potentially toxic materials are required to be added to the fracturing water to be injected into the production zone as the range of permeation may be greater.
Fracturing fluid compositions are inherently “toxic” as result of their make-up and specifically as a result of constituent compounds such as cross-linking agents, viscosifying additives, and any number of low cost additives of various functions that make up a fracturing fluid composition. As a result, there is a significant concern in the event of the fluids coming into contact with groundwater in either a short or longer time frame, and the associated concern that any contaminated fluids would be subsequently consumed by humans or animals. The deepest depth that easily processed and consumable groundwater is found is referred to as the base of ground water in which all deeper sources are saline and thus not fit for human or animal consumption. In CBM production zones, the water contained may either be fresh or saline.
When a fracturing operation is conducted in deep wells (i.e. generally greater than 200 m depth or below the base of groundwater regulations and protection), the toxicity is generally not an issue as the fracturing fluid is diluted by virtue of the migration distance to the groundwater as well as the low vertical permeability and ability of the fracturing fluid to migrate vertically at all through the matrix production zones, including CBM zones, due to cap rocks.
In the case of many shallow formations, operational economics are achieved by completing and stimulating multiple non-economic dry CBM production zones to form a marginal to good overall economic well with commingled production from all CBM zones. All zones could be stimulated at once by injecting down the well through casing only, but coiled tubing is often used to isolate the stimulation of individual zones with the flow back of the fracturing fluids commingled up the casing. When commingled deep (>200 m deep or deeper than base of groundwater) and shallow (<200 m deep or shallower than base of groundwater) CBM production zones are cleaned up and produced together up the casing, fracturing fluids can flow from any one CBM production zone out of the well or into another CBM production zone temporarily based on simple pressure differential. The result is that all CBM production zones in the well are at risk for being exposed to all fracturing fluids pumped into all CBM production zones. This effect, although not usually directly measured in the commingled stimulated well, can be risk assessed through regional bottom hole pressure measurements from offset wells with the same production zones to establish typical reservoir pressures.
However, in shallow wells, toxicity can be a significant problem as the fracturing operation may be conducted in relatively close proximity to groundwater such that the groundwater can be contaminated. For example, in Alberta, Canada, there has been a recent trend to develop shallow gas (commonly CBM) reservoirs less than 200 meters deep (or otherwise above the base of groundwater) using high fracture volumes, pump rates and pressures during such shallow fracturing operations.
In response to these concerns, regulatory agencies such as the Energy Resources Conservation Board (ERCB) (Alberta, Canada) are developing regulations to address these trends to ensure that the effects of these trends do not result in environmental contamination at or away from the well. For example, these regulations are considering imposing on companies conducting fracturing operations some or all of the following, including an effective assessment demonstrating that a complete review was conducted and all potential impacts were mitigated in the designed fracture program. Such an assessment is suggested to include the fracturing program design, including proposed pumping rates, volumes, pressures, and fluids; a determination of the maximum propagation expected for all fracture treatments to be conducted; identification and depth of offset oilfield and water wells within 200 m of the proposed shallow fracturing operations; verification of cement integrity through available public data of all oilfield wells within a 200 m radius of the well to be fractured; and landholder notification of water wells within 200 m of the proposed fracturing operations. These particular policies were introduced during recent times due to the high level of development of shallow, dry CBM wells that are drilled very close to one another.
Other conditions include restrictions for fracturing near a water well, in proximity to bedrock and limitations concerning pumping volumes during a nitrogen fracture. In particular, the use of non-toxic fracture fluids is required. This applies to many of the shallow, dry CBM wells.
In general, “green” or otherwise non-toxic, environmentally friendly fracturing compositions are preferred by society and regulatory agencies from industry. With any well operations including fracturing, there are small environmental risks from surface handling of materials before injection into the well or from recovering the fluids from the well after the frac. In general, preferences and requirements for the fracturing industry are requesting and in the future will require more non-toxic, green or environmentally friendly products. Society and government are particularly demanding when the perception that fresh water sources are at risk through well injection or during times of drought. Moreover, nitrogen condensed from the atmosphere that can be substituted for fresh water to inject into coal wells, reduces demand for fresh water sources leaving them for domestic use. The greater amount that inert nitrogen can be substituted for fresh water use, the more preferential the fracturing composition in turns of its effect on the environment.
The “toxicity” of many fluids is quantified by various protocols acceptable to a jurisdiction for testing the toxicity of a composition in the environment. Different areas or applications may use different protocols. For example, the Environmental Protection Agency (EPA) utilizes different testing protocols for testing soil contamination in different applications.
One set of standards that is generally accepted as a rigorous and meaningful test is the Microtox™ testing protocols for testing the toxicity of compositions in soil. Under the Microtox™ protocols, the viability of known bacterial cultures is measured within a sample to produce a numeric result as well as a “pass/fail” indication.
More specifically, the Microtox™ test is based on monitoring changes in the level of light emission from a marine bioluminescent bacterium, Vibrio fischeri NRRL-B-11177, when challenged with a toxic substance or sample containing toxic materials.
The test is performed by rehydrating freeze dried cultures of the organism, supplied as the Microtox™ reagent and determining the initial light output of homogenized bacterial suspensions. Aliquots of osmotically adjusted sample and sample dilutions are added to the bacterial suspension, and light measurements are made at specific intervals (generally at 5 or 15 minutes) after exposure to test samples. The diluent control (blank) is used to correct time-dependant change in light output.
The Microtox™ test endpoint is measured as the effective or inhibitory concentration of a test sample that reduces light emission by a specific amount under defined conditions of time and temperature. Normally, this is expressed as an ECSO(15) or ICSO(15) which is the effective concentration or inhibitory concentration of a sample that reduces light emission of the test organism by 50% over a 15 minute test period at 15°C.
The EC50 or IC50 is calculated by log linear plotting of Concentration (C) vs percent Light Decrease (percent A), or more precisely by plotting Gamma Q (which is the corrected ratio of the amount of light lost to the amount of light remaining) versus Concentration on a log-log graph. Either a hand calculator or computer program data reduction systems may be used to calculate Gamma and the corresponding EC50 or ICSO values.
As noted above, CBM production zones are unique in how they store and release methane gas, and, in turn, CBM has unique damage mechanisms. Production of methane from CBM wells is a growing unconventional contribution to the gas supply for North America. Further, CBM is damaged by many gelling agents, clay control agents, surfactants, breakers, cross-linking agents, and other chemicals. The chemical damage generally causes a reduction in the rate that methane can desorb from coal. Some gases like liquid carbon dioxide and potentially propane can adsorb onto coal to such a large extent that the coal swells and causes a permeability reduction through reduction of natural fracture porosity and cross-sectional flow area.
Accordingly, there has been a need for the development of non-toxic fracturing fluid compositions that will meet acceptable standards for “non-toxicity” and that generally address the increasing needs for environmentally friendly, green consumable materials used by many industries. There has also been a need to use CBM friendly chemistry that reduces coal damage and otherwise maximizes production. In addition, there are society and government issues to reduce fresh water use, which is addressed by this invention by substituting water with inert nitrogen gas.